In order to improve the recovery of hydrocarbons from oil and gas wells, the subterranean formations surrounding such wells can be fractured. That is, fluid can be introduced into the formations through one or more of well bores, at an elevated pressure (and preferably a pressure sufficiently high to initiate hydraulic fracturing, e.g., 5-120 Mpa) to open the pores and cracks in the formation. The fracturing fluids which are used in this operation are preferably loaded with proppants. Proppants may be any particles of hard material such as sand, which wedge open cracks or pores in the formation, and thereby increase the permeability of the formation once the pressure in the boreholes produced during the fracturing operation is released. For this reason, fracturing fluids are preferably of high viscosity, so as to be capable of carrying effective volumes of one or more proppants.
Fracturing fluids which have been used in the past include aqueous gels and hydrocarbon gels. These are produced by the introduction of cross-linkable polymers such as guar gum and hydroxy ethyl cellulose or the like. One disadvantage with such fluids is that the cross-linkable natural polymer provides a medium upon which bacteria may grow. If a bacteria colony develops in a borehole, then the colony may plug up at least part of the borehole thereby reducing the amount of hydrocarbon which can be recovered. In addition, if the bacteria produce sulphides, then the production of the sulphides can result in a sweet reservoir being converted to a sour reservoir. If this occurs, additional processing steps may be required for the hydrocarbon which is recovered from the borehole, and, in addition, corrosion issues may arise from the exposure of the process equipment to the sulphides. In addition, hydrogen sulfide gas is a poisonous gas which has associated safety concerns.
It has been proposed, for instance in U.S. Pat. No. 5,551,516, to provide a fracturing fluid with good viscosity and little residue by combining an inorganic stabilizer salt, a surfactant thickener and an organic salt or alcohol. The fluid may also comprise a gas, and thereby be in the form of a foam The fluid disclosed in U.S. Pat. No. 5,551,516 develops viscosity of between 150 and 200 cp @ 170 sec−1 at temperature of about 40-50° C., and surfactant loadings of up to 5%.
Particulate material, e.g. clay, can swell and thereby may cause reduced permeability and/or may be dislodged during a fracturing operation. If particulate material bercomes mobile during a fracturing operation, then the particulate material can block some of the pores or fractures in the borehole thereby reducing the potential output of the borehole Accordingly, inorganic salts such as potassium chloride, calcium chloride and ammonium chloride have been added to a fracturing fluid to prevent or reduce particulate material from being dislodged during the fracturing operation Typically, at least 2 or 3 weight percent salt is added to a fracturing fluid as a clay stabilization agent. The addition of such a large amount of salt can result in increased difficulty in processing and disposing of spent fracturing fluid (i.e. fracturing fluid which is recovered from a borehole subsequent to the fracturing operation).